The present invention relates to methods of using fluid loss control additives. More specifically, at least in some embodiments, the present invention relates to the use of fluid loss control additives in drilling and servicing fluids that comprise polymeric micro gels in subterranean operations.
When well bores are drilled into producing formations, drilling fluids are utilized which will minimize damage to the permeability of the formations and their ability to produce hydrocarbons. Servicing fluids are utilized when completion operations are conducted in producing formations and when conducting work-over operations in the formations. The drilling and servicing fluids deposit a layer of particles known as “filter cake” on the walls of the well bores within the producing formations. The filter cake is believed to help prevent the drilling and servicing fluids from being lost into the formation and prevents solids from entering the porosities of the rock. Following completion and prior to initiating production, the filter cake is usually degraded or allowed to degrade to allow product to flow into the well bore for production. Degrading the filter cake is important to retain well bore connectivity and the natural permeability of the reservoir rock. If not degraded or allowed to degrade, the filter cake could present an impediment to production, inter alia, by altering the permeability of the reservoir. Once the permeability of the reservoir has been diminished, it is seldom able to restore it to its original condition. These should be distinguished from the function of additives (sometimes termed in the art “relative permeability modifiers” or “RPMs”) that are often used in conformance or fracturing fluids to permanently seal water influxes to hydrocarbon reservoir areas surrounding a well bore.
Drilling and servicing fluids (such as drill-in fluids) may comprise fluid loss control additives to further assist in preventing the drilling and servicing fluids from being lost into the formations. Drilling fluids are any of a number of fluids and mixtures of fluids and solids (as solid suspensions, mixtures and emulsions of liquids, gases and solids) used in operations to drill boreholes into the earth. Classifications of drilling fluids has been attempted in many ways, often producing more confusion than insight. One classification scheme, given here, is based only on the mud composition by singling out the component that clearly defines the function and performance of the fluid: (1) aqueous-based, (2) oil-based and (3) gaseous (pneumatic). Each category has a variety of subcategories that overlap each other considerably. Ideally, a drilling fluid is non-damaging to the formation, meaning that the fluid does not leave behind particulates, fines, etc. that negatively impact the permeability of the formation.
A drill-in fluid is a fluid designed for drilling through the reservoir section of a well bore in a subterranean formation. The reasons for using a specially designed fluid include, but are not necessarily limited to: (1) to drill the reservoir zone successfully, often a long, horizontal drain hole; (2) to minimize damage to and maximize production of exposed zones; and (3) to facilitate the well completion needed, which may include complicated procedures. A drill-in fluid often resembles a completion fluid in that it may comprise a brine, possibly bridging agents, and/or polymers.
The term “drilling fluid” as used herein refers generically to both drilling fluids and drill-in fluids unless otherwise specified.
Other types of treatment fluids that can utilize fluid loss control materials include, but are not limited to, pills (such as inside screen pills), which are fluids with a relatively small quantity (e.g., less than 200 bbl) of a special blend of drilling fluid to accomplish a specific task that the regular drilling fluid cannot perform. Examples include high-viscosity pills to help lift cuttings out of a vertical well bore, freshwater pills to dissolve encroaching salt formations, pipe-freeing pills to destroy filter cake and relieve differential sticking forces, and lost circulation material pills to plug a thief zone. Another example is a screen pill that may be useful in conjunction with a gravel pack operation.
Examples of conventional fluid loss control additives for water-based treatment fluids include nonionic water soluble polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Fluid loss additives that include starches often vary in the ratio of amylose to amylopectin content, and may or may not be modified with a crosslinking agent such as epichlorohydrin. Also, natural starches may not be uniform in terms of quality and effectiveness. These cross-linked starches often do not have thermal stability at temperatures up to about 250° F., and at temperatures above 250° F., they can only effectively be used by increased loading the treatment fluid with the cross-linked starch, constantly replenishing the treatment fluid with the cross-linked starch, or using an oxygen scavenger in conjunction with the cross-linked starch. At temperatures above 300° F., even by the use of the above mentioned measures, cross-linked starches may not be effective fluid loss control additives.
Conventional linear synthetic polymers are also utilized, but oftentimes, they require another additive, such as a clay, to be able to effectively function as fluid loss control additives. However, the use of clay can be problematic in drill-in fluids, as removing the clay from the subterranean formation can be difficult because it infiltrates into pores of the subterranean formation. Furthermore, the addition of clay to a treatment fluid dramatically increases the viscosity of the fluid, which can cause drilling to be completed at a reduced rate. Another issue is that some synthetic polymers cannot be used successfully in conjunction with some brines, for instance, divalent brines. This brine incompatibility is thought to prevent the synthetic polymer from associating with the clay to forming bridging colloids, which are desirable because they provide a degree of fluid loss, e.g., in a drill-in fluid.